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해양 자원 발 시스템

: Introduction to Offshore Petroleum Production System

Yutaek Seo

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Period Contents

1 Week General introduction, outline, goals, and definition

2 Week

Type of reservoir fluids : Dry gas / Wet gas / Gas condensate / Volatile oil / Black oil

PVT laboratory testing : Constant mass expansion / Differential vaporization / Compositional analysis /

: Oil densities and viscosity / SARA, Asphaltenes, WAT 3 Week

Fluid sampling and characterization

: Bottom hole samples / Drill stem test samples / Case studies

4-5 Week

Thermodynamics and phase behavior

: Ideal gas / Peng-Robinson (PR) / Soave-Redlich-Kwong (SRK)

: Peneloux liquid density correction / Mixtures / Properties calculated from EoS

6 WeekSubsea Field Development

: Field configuration / Artificial rift / Well layout

7 WeekWell components

: Well structures/Christmas tree

8 WeekSubsea manifolds/PLEM and subsea connections

: Components / design / installation

9 WeekUmbilical / risers / flowlines

: Design criteria/ analysis

10 Week

Flow regime

: Horizontal and vertical flow / Stratified flow / Annular flow / Dispersed

bubble flow / Slug flow

11 Week

Flowline pressure drop and liquid holdup

: Frictional losses / Elevation losses / Acceleration losses /

Multiphase flow modeling / slug catcher design / flowline sizing

12 WeekThermal conductivity and heat transfer

: Overall heat transfer coefficient / insulation design

13 WeekFlow assurance issues

: Hydrate/Wax/Asphaltene/Corrosion/Scale

14 WeekField operation

: Operational procedures for offshore petroleum production

15 WeekApplication Example: Offshore platform (Pluto fields), Floating production system (Ichthys fields)

16 Week Final Test

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Slip and liquid holdup in gas-liquid flow

• Under most pipe flow conditions, the liquid moves more slowlythan the gas because it is more dense and viscous.

• Both phases would move through the pipe at the same velocity

if there were no slip between the gas and liquid.

• Liquid holdup is the volume fraction of the pipe that is liquid.

Because of slip, this fraction is generally higher than the fraction

of liquid entering the pipe.

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Steady state multiphase flow modeling

• Most offshore pipelines are sized by use of three design criteria:available pressure drop, allowable velocities, and slugging.

• Line sizing is usually performed by use of steady state

simulators, which assume that the temperatures, pressures,

flowrates, and liquid holdup in the pipeline are constant withtime. This assumption is rarely true in practice, but line sizes

calculated from the steady state models are usually adequate.

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Flowline pressure drop

• The maximum allowable pressure drop in a pipeline isconstrained by its required outlet pressure and available inlet

pressure. In addition, the pressure in a pipeline must always be

less than the maximum allowable operating pressure.

• Allowable pressure drop is a function of the parameters of the

flow system. No fixed criteria exist for determining the maximumpressure drop for a pipeline design.

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Steady state production flowline pressure drops

• Rules of Thumb for Frictional Pressure Drops- Gas or Gas Condensate Production Flowline: 10-20 psi per mile

- Oil Production Flowline: 50-250 psi per mile

- Note: Hydrostatic head needs to be accounted to determine the

total pressure drop

- Conservative estimate for production flowlines (with only reservoirenergy to promote flow): the pressure drop at maximum flowrate

should be about 1/3 of the difference between the initial FWHP and

the required arrival pressure at the host.

• Flowline capacity can be limited by ∆P or by EVR (erosion

velocity ratio)

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Pressure drop in an offshore gathering system

• For a gathering system, the ideal way to check for allowablepressure drop is to simulate the whole system, from the

reservoir to the separator, over the design life of the field.

• This approach will account for the changes in reservoir

pressure, flowrate and compositions in the gathering system

over the-field life.• If rigorous simulations cannot be conducted on a gathering

system, a conservative rule of thumb is to take 1/3 of the

difference between the initial wellhead pressure and the

separator pressure as the allowable pressure drop in the

pipeline/riser system.

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Pressure drop and liquid holdup

• In a multiphase pipeline pressure drop is not always themaximum at the highest flowrate.

• If a pipeline contains significant "hills and valleys", it is possible

that the highest pressure drop occurs at a lower flowrate. This

is due to increased liquid holdup at lower flowrates.

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Flow velocity

• The velocity in multiphase flow pipelines should be kept withincertain limits to ensure proper operation.

• Operating problems can occur if the velocity is either too high or

too low. There are guidelines to determining these limits, but

they are not absolute values.

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Maximum flow velocity and erosion

• Solids Free Erosion Velocity limits can be determined using APIRP14E, given in the equation below. Ve is the maximum

velocity allowed to avoid excessive corrosion/erosion.

Where,

Ve = erosional velocity (ft/s)

C = empirical coefficient

ρmix = gas/liquid mixture density (lb/ft3), which is defined as

Where,

ρmix = liquid density,

ρgas = gas density,

CL = flowling liquid volume fraction (CL = QL / (QL + QG)

mix

e

C V

ρ

=

g L L Lmix ) ρC (1 ρC −+= ρ

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• This equation attempts to indicate the velocity at which erosion-corrosion begins to increase rapidly. This equation is an over-

simplification of a highly complex subject, and as a result, there

has been considerable controversy over its use.

• For wells with no sand present, values of C have been reported

to be as high as 300 without significant erosion/corrosion incarbon steel pipes.

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• For flowlines with significant amounts of sand present, therehas been considerable erosion-corrosion for lines operating

below C = 100.

• Assuming on erosion rate of 10 mils per year, the following

maximum allowable velocity is recommended by Salama and

Venkatesh, when sand appears in an oil/gas mixture flow:

Where,

VM = maximum allowable mixture velocity (ft/s)

d = pipeline inside diameter, in.

Ws = rate of sand production (bbl/month)

s

M

W

4d V =

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Minimum flow velocity

• The concept of a minimum velocity for a flowline is alsoimportant.

• Velocities that are too low are frequently a greater problem than

excessive velocities.

• The following items may effectively impose minimum velocity

constraints:Slugging: Slugging severity typically increases with decreasing flow

rate. The minimum allowable velocity constraint should be imposed

to control the slugging in multiphase flow for assuring the production

deliverability of the system.

Liquid handling: In gas/condensate systems, the ramp-up rates maybe limited by the liquid handling facilities and constrained by the

maximum line size.

Pressure drop: For viscous oils, a minimum flow rate is necessary to

maintain fluid temperature such that the viscosities are acceptable.

Below this minimum, production may eventually shut itself in.

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Problem with flow velocities which are too low

• Liquid holdup may increase rapidly at low mixture velocities.• Water may accumulate at low spots in the line. This may cause

enhanced localized corrosion.

• Low velocities may cause terrain induced slugging in hilly

terrain pipelines and pipeline-riser systems.

• The minimum velocity depends on many variables, including:topography; pipeline diameter; gas-liquid ratio; and operating

conditions of the line. Roughly a value for the minimum velocity

would be a mixture velocity of 5-8 ft/s

(note: API recommends 10 ft/s to minimize slugging)

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Flow in networks

• A basic approach for networks outlined by Gregory & Aziz(1978) relies on an initial knowledge of the flow from each feed

of a gas gathering system, the details of each flowline section

(construction, topography etc.) and the pressure and

temperature at the outlet (final gathering point).

• Calculations are performed backwards through the system toascertain the pressure and temperature at each node.

• This approach may require many iterations to study constraints

and limitations at supply wells and/or the arrival point.

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Line sizing

• Unlike single-phase pipelines, multiphase pipelines are sizedtaking into account the limitations imposed by production rates,

erosion, slugging, and ramp-up speed. Artificial lift is also

considered during line sizing to improve the operational range of

the system.

• The line sizing of the pipeline is governed by the followingtechnical criteria:

Allowable pressure drop;

Maximum velocity (allowable erosional velocity) and minimum velocity;

System deliverability;

Slug consideration if applicable.

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• Other criteria considered in the selection of the optimum linesize include:

Standard versus custom line sizes;

Ability of installation;

Future production;

Number of flowlines and risers;Low-temperature limits;

High-temperature limits;

Roughness.

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Exercise

• Determine optimum flowline ID from reservoir pressure, PI,wellbore hydraulics data, flowline hydraulics data and required

rate and arrival pressure.

- Reservoir: P = 7000 psia, T = 200 oF, Well PI = 20 bpd/psi

- Vertical Wellbore (4 wells): 10,000 ft x 4.625” ID; Oil: 10,000 bpd,

10 cP & 0.80 g/cc- Flowline: 50,000 ft long, 2000 ft elevation increase; Oil: 40,000 bpd,

25 cP & 0.75 g/cc

- Riser: 3000 ft vertical; Oil: same as flowline

- Required arrival pressure = 500 psia

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Reservoir

P = 7000 psia, T = 200 oF

Well PI = 20 bbl/psi

1. Flowing bottomhole pressure at 10,000 bpd

: 7000 psi – 10,000 bpd/20 bpd/psi = 6500 psia

Surface

Subsurface

Four wells & vertical wellbore

10,000 ft * 4.625” ID; oil: 10,000 bpd, 10 cP & 0.80 g/cc

Flowline: 50,000 ft long, 2000 ft elevation increase;

Oil: 40,000 bpd, 25 cP & 0.75 g/cc

Riser: 3000 ft vertical;

Oil: same as flowline

Required arrivalpressure = 500 psia

2. Flowing wellhead pressure at 10,000 bpd

: 2906.8 psia

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3. Generate diagram for flowline ID vs arrival pressure

0.0

100.0

200.0

300.0

400.0

500.0

600.0

700.0

6.800 7.000 7.200 7.400 7.600 7.800 8.000 8.200

A r r i v a l p r e s s u r e

Flowline ID (in)

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Transient Multiphase flow simulator

• Steady state simulators assume that all flow rates, pressures,temperatures, etc. are constant through time. For transient

phenomena, such as slug flow, only average values of holdups

and pressure drops are calculated.

• Transient simulators show the variations in parameters such as

pressure, temperature, and gas and liquid flow rates as afunction of time and can model dynamic phenomena such as

slug flow.

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Development of transient multiphase flowsimulator

• Transient multiphase flow simulators were developed inresponse to the growing need to model flow in offshore

production lines.

• The first widely used commercial program, OLGA (marketed

commercially by Scandpower), began development in about

1983 and has been commercially available since 1990.• One of OLGA's current competitors, PLAC (now called ProFES

and marketed by AEA), was introduced to the market at about

the same time. A transient simulator called Tina, which was

developed by IFP and marketed by SimSci, is also available.

• LedaFlow: Multi-dimentional multiphase flow simulatordeveloped by SINTEF based on improved understanding of

multi-phase physics, large-scale experiments and field data.

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Characteristics of transient multiphase simulators

• Transient simulators more closely model the operation ofpipelines and with more detail than do steady state simulators.

• Transient simulators solve a set of equations for conservation of

mass, momentum and energy to estimate liquid and gas flow

rates, pressures, temperatures and liquid holdups as a function

of time.• The programs utilize an iterative procedure that ensures a set

of boundary conditions (such as inlet flow rates and outlet

pressures as a function of time) are met while solving the

conservation equations.

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Uses of transient multiphase simulators

• Transient simulators are needed for situations including:startup and shutdown,

warm up and cool down of flowlines,

unsteady flow of liquid and gas into receiving facilities (separators

and slug catchers),

and pigging.• In addition, OLGA2005 includes the ability to estimate the flow

of all three phases (oil, gas, and water). At low production rates,

the distribution of oil and water in the holdup liquid will be more

accurately predicted when using three-phase simulation.

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Applications for transient multiphase simulators

• The uses for transient multiphase flow simulators include:- Slug flow modeling

- Estimates of the potential for terrain slugging

- Pigging simulation

- Identification of areas with higher corrosion potential, such as water

accumulation in low spots in the line and areas with highlyturbulent/slug flow

- Startup, shutdown and pipeline depressurizing simulations

- Slug catcher design

- Development of operating guidelines

- Real time modeling including leak detection- Operator training

- Design of control systems for downstream equipment

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Flowline depressurization or blowdown

• Depressurization generally refers to the relatively slowevacuation of a pipeline system. Blowdown generally refers to

the rapid evacuation of a pipeline.

• Depressurizing is usually performed to make the pipeline

available for maintenance or repair. Depressurizing a pipeline

will usually take quite a few hours or even days.• Pipeline blowdown will generally take a few hours. Blowdown is

sometimes referred to as emergency depressurization. Pipeline

blowdown is often used to minimize the potential for hydrate

formation during a shutdown and to remove the hydrostatic

head rapidly.• The terms blowdown and depressurization are sometimes used

interchangeably

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Blowdown fluid rates

G a s f l o w r a t e ( M M s c f d )

L i q u i d f l o w r a t e ( b b l / d )

Time (hr)

Start time of blowdown

Blowdown time ~1hr

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Flowline T & P profiles during blowdown

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Blowdown results

Scenario Liquid rate (bpd) Gas rate

(MMscfd)

Flowline highest

pressure

(psia)

Volume of liquid

(bbl)

Normal

production

40,000 40 5500 NA

Blowdown

Maximums

68,000 66 1600

(after blowdown)

1069

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Ramp up flowrates and pressure

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Slugging

• Types:- Hydrodynamic Slugging

- Terrain Slugging

• Conditions for slugging

- 2- or 3-Phase flow

- Elevation changes (seafloor profile)

- Flowrate changes

• Operations which cause slugging:

- Ramp up

- Start-up/Blowdown- Pigging

Caused by flowrate changes

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Moderate flowrate slugging

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Low flowrate slugging

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Low flowrate slugging characteristics

Liquid

production rate

(STB/d)

5,000 10,000

Water cut (%) 10 80 10 80

Slugging

frequency (1/hr)0.5 0.8 2.2 0.72

Max. slug volume

(bbl)330 279 242 257

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Slugging during ramp up and pigging

• Ramp Up:: Total Liquids Produced =

holdup at the lower flowrate (minus) holdup at the higher rate.

: The actual liquid production rate during this period will depend on

the fluids, the flowline design and the flow conditions.

• Pigging: The greatest effects on liquid production during pigging

occur with gas condensate flowlines. The entire flowline liquid

holdup (except for the pig by-pass volume) will be produced in

front of the pig.

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Need for a slug catcher

• During non-steady state conditions (such as start-up, shutdown,turndown, and pigging) or when slugging during normal

production occurs (low flowrates)

• The process controllers alone may not be able to sufficiently

compensate for the wide variations in fluid flow rates, vessel

liquid levels, fluid velocities, and system pressure caused by theslugs

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Slug catcher function – liquid/gas separation

• Process stabilization is the primary purpose of the slug catcher.• A slug catcher provides sufficient volume to dampen the effects

of flow rate surges in order to minimize mechanical damage

and deliver a more even supply of gas and liquid to the rest of

the production facilities; minimizing process and operation

upsets.• A second function of the slug catcher is to provide preliminary

separation of multiphase production fluids into separate gas

and liquid streams. This is done to improve the efficiency of the

process separator.

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Slug catcher design

• The goal of a slug catcher design is to properly configure andsize the slug catcher for the production flowline conditions.

• The design steps are as follows:

1. Determine the functional requirements

2. Determine slug catcher location

3. Select the preliminary slug catcher configuration4. Compile design data

5. Establish the design criteria

6. Estimate the slug catcher size and dimensions

7. Review for feasibility and repeat steps 2-6 as necessary

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Vertical slug catcher

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Subsea slug catcher

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Gas condensate flowline slug catcher

• Ormen Lange

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Next Class

: Thermal conductivity, heat transfer

Homework 8.

Determine flow regime

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